Apparatus and method for subsea well drilling and control

ABSTRACT

A subsea assembly suitable for subsea drilling and intervention operations includes a dual blowout preventer system having an upper blowout preventer located between a drill floor and a high pressure riser string, and a lower blowout preventer located below the riser string and above a wellhead. The dual blowout preventer system is adapted to enable advanced drilling and intervention operations such as managed pressure drilling, underbalanced drilling, dual gradient drilling, or through tubing rotary drilling, and slim hole drilling in an offshore deepwater environment.

BACKGROUND Priority

The present application claims the benefit of U.S. Non-ProvisionalApplication Ser. No. 12/958,802, entitled “ASSEMBLY AND METHOD FORSUBSEA WELL DRILLING AND INTERVENTION” filed Dec. 2, 2010 which claimspriority to U.S. Provisional Patent Application Ser. No. 61/265,805,entitled “SUBSEA WELL DRILLING AND INTERVENTION METHOD AND APPARATUS,”filed on Dec. 2, 2009, naming Gavin Humphreys as inventor, both of whichare hereby incorporated by reference in their entirety.

Field of the Invention

The invention relates to subsea equipment and assemblies of equipmentused in offshore deepwater drilling, completion, production, andintervention operations and the location and recovery of hydrocarbons.In all such operations it is considered essential that the well operatormaintains control of the well and its contents.

Background of the Invention

The search for recoverable hydrocarbons has been the subject ofsubstantial commercial interest and activity for many years.Historically, drilling for and recovery of hydrocarbons has been limitedby the technology available to operating and service companies who wereactively looking for recoverable hydrocarbons on land or in relativelyshallow water. As technology has improved, the geographic and temperatelimitations typically associated with oil and gas exploration havegradually been reduced or removed altogether.

The expansion of hydrocarbon exploration to deepwater locations haspresented severe obstacles to the oil and gas industry, obstacles thatcontinue to be overcome by new technology. As oil and gas explorationgoes into deeper and deeper water the problems associated with the safe,economical, and environmentally satisfactory operation of drilling,completion, production, and intervention operations have beencompounded. In executing any of these operations it is critical thatcontrol of the well and its contents be maintained. There is acontinuing need for solutions to the problems that are encountered indeepwater drilling, problems that are not typically encountered in landbased drilling or in drilling in shallow water, which for purposes ofthis application is defined as 1000 feet of water depth or less. For theconvenience of the reader, the following alphabetical chart is providedexplaining the meaning of abbreviations used throughout thisapplication:

API American Petroleum Institute

BOP Blowout preventer

DGD Dual gradient drilling

IADC International Association of Drilling Contractors

ID Inner diameter

LBOP Lower blowout preventer

LRP Lower riser package

MPD Managed pressure drilling

MW Megawatts

OD Outer diameter

PMCD Pressurized mud cap drilling

RCH Rotating control head

ROV Remotely operated vehicle

SG Specific gravity

TD Total depth/arrival at the desired well depth and location

TTRD Through tubing rotational drilling

UBD Underbalanced drilling

UBOP Upper blowout preventer

VBR Variable bore rams

One particular need has been the design and testing of the equipmentnecessary to connect the drilling vessel at the surface to the wellheadat the ocean floor. The pressures that such equipment must be designedto handle are enormous and the risks associated with the failure of suchequipment are catastrophic. In virtually every deepwater subsea well atleast one blowout preventer (sometimes referred to herein as a “BOP”) isinstalled at the ocean floor to seal the drill pipe or annulus duringemergency situations, typically caused by hydrocarbons from formationsbeing drilled, in which unanticipated hydrocarbons are not contained bythe drilling or casing equipment. In some instances, two or more blowoutpreventers are stacked on one another at the wellhead location. It isimportant in the design of subsea drilling equipment that the equipmentis designed to keep formation gases, which are rapidly expandable aswell as flammable, out of the riser or the floating support structure.

As an alternative protective measure, some deep water drilling vesselshave installed a blowout preventer at the surface to maintain wellcontrol but seldom have both a subsea BOP and surface BOP been installedtogether.

What is common to both systems is a Lower Riser Package (“LRP”) that isinstalled below the riser string and above the subsea BOP or LBOP thathouses the termination of control umbilicals to the subsea devices andhas a hydraulic activated connector that will enable the LRP to bedisconnected in the event of an emergency.

However, what has not been addressed is the specific design of theequipment that connects two such blowout preventers, one at the oceanfloor and one at the surface. This invention addresses and provides asolution to a long felt need for a subsea assembly that provides safetynot only at the ocean floor and at the surface but also between thosetwo points in deepwater operations.

What must be understood to truly appreciate this invention is the factthat normally what is called a marine riser is used to connect the oceanfloor blowout preventer to the surface structure, whether the surfacestructure includes a second blowout preventer or not. Such a marineriser is not suitable to withstand the pressures associated withemergency situations such as experienced during a “pressure kick” or“pressure surge” if such pressures are not neutralized by one or bothblowout preventers. In such situations the well operator loses controlof the well and its contents. The apparatus and method of this inventionprovide improved control of the well and its contents duringunanticipated pressure conditions.

One important advantage of the subsea assembly of this invention is theability to activate shear rams in the subsea BOP to secure the wellprior to disconnecting at the LRP in the event of an emergency. Whilesuch shear ram activation would only occur during extreme situations, itprovides a measure of safety to the floating support structure and theindividuals on such a structure and helps prevent the escape offlammable fluids into the floating support structure during emergencysituations. The escape of such flammable fluids inevitably leads to fireand explosions.

Furthermore, it must be understood that under certain circumstancesadvanced drilling techniques are used in deep water drilling that mayincrease the risks associated with formation based pressures between theocean floor and the surface. These advanced drilling techniques includemanaged pressure drilling, underbalanced drilling, through tube rotarydrilling, and dual gradient drilling. The apparatus and methodsassociated with this invention enhance the ability to use such advanceddrilling techniques without exposing the operators or environment toundue risks.

Description of the Related Art

Exploration for and recovery of hydrocarbons often requires theplacement of drilling equipment in an offshore location. In shallowwaters, the rigs and production facilities can be placed on freestandingoffshore platforms. As the water becomes deeper, however, use of suchplatforms becomes impractical. As a result, floating structures, such asdrill ships, must be used.

As the desire to drill at greater water depths increases (e.g., to atleast 10,000 ft. water depth), floatable support structures have becomelarger due to the amount of pipe and other logistical support requiredto drill at such depths. In order to facilitate drilling in deep waterlocations, drill ships have been specifically designed to be selfcontained drilling structures that contain most, if not all, of theequipment necessary to carry out deep water drilling, completion,production, and intervention procedures. The dimensions of many suchdrill ships are such that they are difficult to navigate through canalsand other confined locations. In addition, the physical size andvertical height of the drilling structure, such as a single drillingderrick, double drilling derrick with two drilling centers, hydraulicram drilling structures, or other type of hoisting tower on the shipalso limits the locations in which it can travel. For example, largedrillships may not be able to travel through such waterways as the Suezor Panama Canals due to width and depth constraints of the canals, andlikewise may not be able to travel under the bridge in the Bosphorous(mouth of the Black sea) due to the height of their drilling derricks orhoisting tower on the drillship. It is often necessary to travel aroundsuch waterways, which greatly increases the travel costs and time.

In addition, conventional deepwater rigs cannot efficiently perform someadvanced drilling operations. For example, in recent years, ManagedPressure Drilling (“MPD”) and it's derivative, Underbalanced Drilling(“UBD”), Dual Gradient Drilling (“DGD”),and through tubing rotationaldrilling (“TTRD”) utilizing MPD or UBD have become increasingly morerelevant to drilling wells that were previously deemed un-drillable orto drill wells where subsurface pore pressures and fracture gradientshave converged requiring drilling with tailored drilling fluid weightssupported by surface back pressure to drill through very tight porepressure-fracture pressure windows.

As technically defined by the IADC, Managed pressure drilling is “anadaptive drilling process used to precisely control the annular pressureprofile throughout the wellbore. The objectives are to ascertain thedownhole pressure environment limits and to manage the annular hydraulicpressure profile accordingly.” In more conventional terms, MPD meansthat drillers maintain bottomhole pressure equal to or greater than theformation pore pressure by tailoring the density of drilling fluids anddrilling with controlled back pressure between the seals of the RCH andthe MPD choke manifold. When the bottom hole pressure gets too high, aportion of the drilling fluid can be lost to the formation, whichdamages the porosity of the formation (known as “skin”) as well as beinga very expensive if loss of drilling fluid is substantial. The solutionis that casing must be set to isolate the formation from the drillingfluid. This results in more strings of casing and more expense to thedriller, all of which can be avoided by managing the pressure of thedrilling fluid throughout the wellbore.

As opposed to MPD, UBD is a procedure used to drill oil and gas wellswhere the pressure in the wellbore is intentionally kept lower that thefluid pressure in the formation being drilled. This results in formationfluids flowing into the wellbore and up to the surface. Among theadvantages of using UBD techniques are an increase in the rate ofdrilling penetration caused by less hold down pressure at the bottom ofthe wellbore. Another advantage is a reduction in the loss of drillingfluid into the formation creating “skin”, but by far the greatestadvantage is the ability to characterize a reservoir while drilling byanalyzing the formations and the fluids and production rates containedwithin them at surface.

Yet another advanced drilling technique that is facilitated by theapparatus of this invention is referred to as dual gradient drilling.The IADC defines DGD as “the creation of multiple pressure gradientswithin select sections of the annulus to manage the annular pressureprofile. Methods include use of pumps, fluids of varying densities, orcombinations of these.”

One of the real advantages associated with the use of the advanceddrilling techniques disclosed herein is the ability to extend the lengthof drilling sections before casing is required. By extending drillingsections, fewer casing sizes are required and less downtime fromdrilling is required for casing and cementing operations.

An obvious spin-off of reducing the number of casings in a well design,where the subsurface geology and pressure regime would allow and wherethese drilling technologies would be applied, would be slim holedrilling where the well could be drilled and smaller casing set whilemaintaining the same size completion string that is currently in use.

As will become evident from the description of the apparatus and methodof this invention that follows, a critical requirement of all of theadvanced drilling techniques is that the driller or well operatormaintain control of the wellbore and its contents at all times. Suchcontrol is not always possible with conventional drilling equipment andmethods.

The conventional deepwater rigs that utilize a single subsea blowoutpreventer on the seabed which is tied back to the drillship with arelatively low pressure marine riser that is not designed to withstandclosed in internal pressure (designed for flow only) lack the pressureintegrity in the riser to routinely carry out either MPD nor UBD due tothe marine risers' lack of internal pressure integrity (typically a 21¼inch deep water marine riser has a burst pressure at the time ofmanufacture of approximately 5,000 psi, which cannot be field testedduring the riser's life-time). Never the less, the burst pressure of adeepwater riser varies from top to bottom when in situ and is alwayssubject to the drilling fluid weight in the hole and the tension appliedto the riser at the top.

Limited MPD, presssurised mudcap drilling (PMCD) can be performed wherea rotating control head is installed onto a collapsed telescopic jointbut it remains costly due the time it takes to rig up and rig down theMPD equipment. New technology is emerging where the RCH and flow spoolsare integrated into the marine riser string.

Although some pressurized interventions are being done from rigs, theyinvolve dedicated intervention risers (typically slimcompletion/production riser for intervention with electric or slickwire-line, Coil Tubing, or through tubing rotary drilling (“TTRD”))generally with increased costs as they are provided by a third partycontractor to compliment the conventional drilling BOP system.

In view of the foregoing, a need exists for highly mobile floatablestructures capable of drilling in deepwater environments. It would beadvantageous if the structures were smaller than conventional floatablestructures and cost substantially less to build and operate. Inaddition, there is a need for a floatable structure capable of utilizingdrilling technologies such as MPD, UBD, DGD, and TTRD in deepwaterenvironments.

SUMMARY OF THE INVENTION

Floatable structures used in deepwater drilling and intervention areprovided as embodiments of the present invention. The systems andmethods described herein allow operators to safely perform MPD, UBD, DGD, TTRD and slim hole drilling in deep water applications. In anexemplary embodiment, the floatable structure includes a dual BOP systemcomprising an upper blow out preventer (“UBOP”) and a lower blow outpreventer (“LBOP”) with a Lower Riser Package (LRP) to enable adisconnect of the riser system from the LBOP in the event of anemergency or bad weather. The UBOP is located between the drill floor ofthe floating support structure and above a high pressure riser string,while the LRP and LBOP are located below the high pressure riser stringand above a wellhead. The high pressure riser utilizes a slim designwith the same pressure rating as the UBOP and the LRP/LBOP combination.

The UBOP, LBOP, and high pressure riser combine to form a unique risersystem that has the same high pressure integrity from top to bottom,essentially forming an extension of the wellbore to surface. Inaddition, because of the high pressure integrity of the riser almost allapplications of MPD, UBD, TTRD and slim hole drilling (utilizingexpandables as an option) allows wells being drilled using thetechnology of the present invention to be designed to effectively reducethe number of casing strings by using MPD or UBD drilling technology.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram of a dual BOP system made in accordance with anexemplary embodiment of the present invention; and

FIG. 2 is a diagram of a slim hole casing design when expandables may berun in accordance with an exemplary methodology of the presentinvention.

FIG. 3 is a side view of a section of high pressure riser used in thecombination of this invention.

FIG. 4 is a cross section of the high pressure riser of this inventiontaken at line A-A of FIG. 3.

FIG. 5 is a cross section of the high pressure riser of this inventiontaken at line B-B of FIG. 3.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments and methodologies of the invention aredescribed below as they might be employed to allow users to performadvanced drilling and intervention operations in deep waterenvironments. In the interest of clarity, not all features of an actualimplementation or methodology are described in this specification. Itwill, of course, be appreciated that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developers' goals, such as compliance withsystem-related and business-related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time-consuming, but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure. Further aspects andadvantages of the various embodiments of the invention will becomeapparent from consideration of the following description and drawings.

Referring to FIG. 1, an exemplary embodiment of the present invention isillustrated. As shown in FIG. 1, a floatable structure includes a vessel(not shown), such as a drill ship, dual BOPs, and a high pressure risersystem including a lower riser package coupled to and extending beneaththe floor of the vessel. Dual BOP/high pressure riser system 5 comprisesan upper blow out preventer 10 and a lower blow out preventer 20. A highpressure riser string 40 extends between the UBOP and the LBOP. As willbe described in detail later, the drill ship may be a DrillSLIM™ orSLIMDRILL™ drill ship designed by Stena Drilling Ltd. of Scotland, U.K.,which is the Assignee of the present invention.

In one preferred embodiment of this invention the subsea assemblyincludes an assembly 18, including rotating control head 19 connectingthe floating support structure, the floor of which is shown as 35 inFIG. 1, to an UBOP 10, the UBOP 10 being operatively connected to a highpressure riser 40, and a lower riser package 80 connecting the highpressure riser 40 to the LBOP 20.

In one such preferred embodiment, the UBOP 10 is located below drillfloor 35 and above high pressure riser string 40. LBOP 20 is locatedbelow high pressure riser string 40 and above a wellhead (not shown). Abag preventer (not shown) may also be located above UBOP 10. Extendingbelow drill floor 35 is a diverter assembly 12 having a flex joint 14coupled beneath it. Diverter assembly 12 may include, for example, 16inch overboard lines to the port and starboard sides of the ship.

Flex joint 14 connects to slip joint assembly 16, which can be a triplebarrel slip joint assembly having a 50 ft stroke. Assembly 18 is coupledbeneath slip joint assembly 16 and includes a high pressure spacer jointwith a load ring and Blafro flange, which is a flange designed to sealaround the base of a high pressure riser that is extended through therotary table where coil tubing BOPs are installed. This assembly,together with the high pressure riser 40, will enable coil tubing workto be performed in the well under high pressure conditions. As shown byFIG. 1, this exemplary embodiment includes a rotating control head(“RCH”) 19 in assembly 18, which is installed above the high pressurespacer joint to enable MPD and its derivative drilling techniques, DGDand UBD, to take place. In addition to MPD, DGD and UBD, other drillingtechniques can be used with the present invention as will be apparent tothose of skill in the art having the benefit of this disclosure.

A flexible line 21 is tied into an independent choke manifold 23, whichmay be located in the substructure of the drill ship or other floatingsupport structure, to facilitate the application of MPD, DGD or UBDdrilling technology, where continuous back-pressure is applied whereapplicable, and is totally independent from the main rig kill and chokelines.

Further referring to the exemplary embodiment of FIG. 1, UBOP 10 iscoupled beneath assembly 18 and in one preferred embodiment includes atleast three sets of rams, 25 a, 25 b, 25 c, wherein at least two of thethree sets of rams comprise variable bore rams (“VBR”) rated at 10K psi.In the alternative, rams 25 a, 25 b, and 25 c include one 9⅝ inch casingram (if the invention is used for slim hole drilling) and two 2⅞-5.5inch VBR. In the most preferred embodiment of this invention one of rams25 a, 25 b, or 25 c may be a blind shear ram, but this is notnecessarily mandatory, but subject to the user's intent and needs. UBOP10 can also include, for example, a 13⅝ inch annular preventer rated at5K psi. Upper stress joint 22 is coupled beneath UBOP 10 and connects tohigh pressure riser string 40, and may be a 13⅝ inch triple barreledtelescopic joint with up to a 50 ft stroke. UBOP 10 also includes achoke/kill manifold with inlets from below the rotating elements of theRCH 19 and an independent choke manifold with self-adjusting chokes forMPD, DGD, TTRD, and UBD operations.

A rotating control device or rotating control head (“RCH”) 19 is a drillthrough device with a rotating seal that contacts and seals against thedrill string for the purpose of controlling the pressure or fluid flowto the surface. Typically, the RCH 19 is a low pressure sealing deviceused in drilling operations utilizing any drilling fluid whosehydrostatic pressure is less than the formation pressure, to seal aroundthe drill stem above the top of the BOP stack, in this case above theUBOP. An internal sealing element seals around the outside diameter of atubular and rotates with the tubular. The tubular may be strippedthrough the RCH 19 while the tubular rotates or when the tubular, suchas a drill string, casing, or coil tubing is not rotating. The internalseal may be passive or active. RCHs have been used to contain annularfluids under pressure, and thereby manage the pressure within thewellbore relative to the pressure in the surrounding earth formation. Inthe invention of this disclosure, it is important that the RCH 19 beinstalled on top of the UBOP to ensure containment and control ofdrilling fluids by applying back-pressure while drilling.

A drilling riser is typically defined as a conduit that provides atemporary extension of a subsea hydrocarbon well to a surface drillingfacility. Drilling risers are categorized into two types: marinedrilling risers used with subsea blowout preventers and generally usedby floating vessels; and tie-back drilling risers used with surfaceblowout preventers and are generally deployed from fixed platforms orvery stable floating platforms such as a spar or tension leg platform.The assembly of this invention is unique in that it utilizes both anUBOP and a LBOP with an interconnecting high pressure riser tofacilitate advanced drilling techniques as described herein.

High pressure riser string 40, as illustrated by FIGS. 3-5, may be a 13⅝inch inner diameter (“ID”), high pressure 10K riser, having kill andchoke lines from the seabed to the surface. Conventional drilling marinerisers (generally utilized with a subsea BOP on the seabed) are designedto control drilling fluid flow and have sufficient burst pressurestrength at the seabed to hold the pressure differential between theheaviest drilling mud inside the riser against seawater pressure outsidethe riser. A high pressure riser can also withstand these physicalproperties, but it can also be sealed up at the top of the riser and besubjected to up to 10,000 psi additional pressure in the event that anactivity may require the riser to be pressured. High pressure riserstring 40 may also include a design that includes a 10,000 psi burstrating, and also be able to comply with stringent dimensionalrequirements for handling and storage on the deck of the drill ship tokeep the ship size to a minimum The subsea assembly of this invention,including the high pressure riser and the UBOP and LBOP are designed tomaintain pressure integrity in the system, even during emergencysituations. It is clearly preferred to keep formation gases out of theriser system altogether, however, if such gases bypass the LBOP and getinto the high pressure riser of this invention, pressure integrity ofthe subsea assembly can be maintained while the gases are bled offbefore causing damage or explosions to the floating support structure.

Referring to FIG. 3 a section of a high pressure riser 40 that could beused in the assembly of this invention is shown. Due to the weight ofthe riser column in deep water drilling operations, which issubstantially greater than a typical marine riser, a series of buoyancymodules 64 are used on the riser string 40 to reduce the absolute weightof the riser column, which must be hung off the floating supportstructure.

Referring now to FIGS. 4 and 5, the cross sectional details of the highpressure riser can be more readily understood. The riser itself isidentified by reference number 61 and typically would be made of steelat a thickness of 1.25 inches. A typical marine riser would have a wallthickness of less than 1.00 inch and would not be rated to withstand thepressures necessary for deep water drilling using the advanced drillingtechniques described above, namely, UBD, DGD, MPD, and other drillingtechniques that involve potential pressure kicks from formationhydrocarbons. A series of hydraulic lines 62 and drilling fluid boostlines 63 are found outside of the riser 61 but within buoyancy modules64 to transfer fluids along the length of the riser column.

By way of example, the high pressure riser 40 can be approximately 7,500ft of 13⅝ inch ID×10K (120 joints) with two choke/kill lines which wouldallow for high pressure pumping outside riser string 40. The joints canbe 65 ft long with high strength connectors, weigh +/−21T (dry), andhave a 45 inch outer diameter (“OD”) with buoyancy. High pressure riserstring 40 is kept in tension by a substructure mounted tensioner system,rated to 2.4 million lbs with 14.0 ppg (1.68 specific gravity (SG))fluid inside the riser.

The high pressure riser system also has 10,000 psi kill and choke line(generally associated with subsea BOP control systems) to facilitateconventional seabed well control techniques or to monitor and controlpressures below a sealed LBOP if the riser system is used as alubricator while using MPD or UBD drilling technologies.

In further reference to the exemplary embodiment of FIG. 1, a lowerriser package 80 is provided, the lower riser package 80 is designed todisengage the riser from the LBOP during emergency disconnectsituations, and includes pods 81 for housing the hydraulics foractuating the disconnect apparatus, a connector 82, and a Mux cable 83.The Mux cable is well known to persons of ordinary skill in the art andcommercially available from a number of well known vendors. In itsbroadest form, the Mux line provides and houses the hydraulic fluids andcontrol signals necessary to operate the lower riser package duringemergency situations. The Mux line is connected to the floating supportstructure and is typically attached to the exterior of the riser string.

LBOP 20 includes at least three sets of rams 30 a, 30 b, 30 c, which caninclude, for example, one pipe ram to hang-off the drill pipe and twoblind shear rams with fail safe closed connections to monitor pressurebuild up in the event the well is closed in on the blind rams. LBOP alsoincludes an emergency disconnect and a wellhead connector. In thealternative, LBOP 20 may be comprised of super shear blind/shear rams inorder to shear and seal on the 9⅝ inch casing and heavier drill pipe.LBOP 20 and the lower riser package 80 enable the well to be closed inat seabed level, and the high pressure riser string 40 to bedisconnected.

In this exemplary embodiment, LBOP 20 and the lower riser package 80 arecontrolled by a multiplex system with acoustic backup including:duplicate umbilical control reels for approximately 7500 ft water depthand a modular emergency subsea accumulator pack (set on seabed) that isconnected using a remotely operated vehicle (ROV). UBOP 10 can becontrolled by a pilot hydraulic control system. The controls for bothUBOP 10 and LBOP 20 can be adjacent to each other on the same panels.The hydraulic disconnect package or lower riser package 80 can includean inverted connector with acoustic control back up. Those ordinarilyskilled in the art having the benefit of this disclosure realize theseand a variety of other components may be utilized within the lower riserpackage 80 of the present invention.

Accordingly, through the use of LBOP 20, high pressure riser string 40,UBOP 10, and an RCH 19 designed into the riser system, the presentinvention provides the ability to utilize MPD, DGD, TTRD, and UBD indeepwater offshore applications. High pressure riser string 40 and UBOP10 act as an extension of the wellbore for drilling operationsfacilitating MPD and UBD operations. As such, the riser system betweenUBOP 10 and LBOP 20 holds the same pressure as UBOP 10 and LBOP 20,thereby creating a deepwater drilling BOP and riser system that has thesame high pressure integrity from top to bottom. Similarly, highpressure riser string 40 can act as a very long lubricator forpressurized well interventions by also using LBOP 20 and UBOP 10together with an RCH for MPD, UBD, DGD and TTRD well interventionapplications.

Referring to the exemplary embodiment of FIG. 2, the present inventionprovides the ability to drill a slimmed down well design where anexpandable liner may be used as a contingency. The concept of DrillSLIM™drilling technology has been developed to make the drilling of a wellmore efficient, and therefore less expensive. In its most basic form,drilling slim wellbores involves the use of the advanced drillingtechniques disclosed in this application in order to extend the lengthof each sequential string of casing from what is considered the norm indeepwater well drilling. By using fewer casing strings, the telescopiccross section of a cased wellbore, as shown in FIG. 2, is minimized sothat the desired casing size is maintained at TD or the production zone,but the number of increasingly large case strings necessary to arrive atTD is reduced, thereby saving time and expense.

Another form of a DrillSLIM™ wellbore drilling is generically describedas an “expandable.” Again, in its most fundamental form, expandabletechnology involves inserting a relatively small diameter casing stringinto a wellbore, inserting a smaller diameter casing string through thefirst casing string and into the wellbore, and then using a swedge orother mechanical means to physically expand the smaller diameter casingto the same diameter as the casing string immediately above. The use ofexpandable technology in its most advanced form can result in thedrilling of a deepwater well that is essentially a uniform diameter fromthe wellhead to the production zone.

An exemplary method of the present invention will now be described.Expandable liners, as understood in the art, are utilized in thisexemplary methodology. The well of FIG. 2 is located at a water depth ofapproximately 7,500 ft, having a total depth (“TD”) of approximately22,500 ft. Surface casing 42 and intermediate casing 44 are run andcemented prior to running the 13⅝ inch×10,000 psi dual BOP/high pressureriser system 5. Generally, intermediate casing 44 will be one API sizesmaller than the typical casing run before the placing of a BOP in aconventional well design. For example, intermediate casing 44 may be a13⅜ inch casing string, while such casing would typically be a 20 inchcasing string in a conventional well design.

After setting surface casing 42 and intermediate casing 44 (13⅜ inch),dual BOP/high pressure riser system 5 is run. Thereafter, the next holesection is drilled with a 12¼″ bit to section TD. In the event this TDcannot be achieved through some subsurface issues, then the 12¼″ holesection will be opened with a bi-centered bit or under-reamed to 16inches/17½ inches. Then, solid expandable liner 48 is run and expandedto seal at the junction of shoe 46. In this exemplary embodiment,expandable liner 48 is an 11¾ inch OD solid expandable liner that whenexpanded has the same drift diameter as the previously set 13⅜ inchcasing. This now makes the casing shoe depth of the present inventionequivalent to that of a conventional casing design. Those skilled in theart having the benefit of this disclosure realize that in wells thatonly require four casing/liner strings to get to TD, or have a TD linersmaller than 7 inches, the use of expandable liner may not be necessary.Additionally, those same skilled persons realize other casing/linertypes may be utilized with the present invention. Once expandable liner48 is set, then all further drilling activity will be performed asunderstood in the art.

Further referring to the exemplary methodology of FIG. 2, in order tosecure the 12¼ inch drift for expanded casing/liner, the expansionsystem and method must be taken into account to determine the necessarysurface casing size, as would be understood by one skilled in the arthaving the benefit of this disclosure. The well can then be drilled witha 12¼ inch bit for a 9⅝ inch casing string 50 or a 9⅝ inch liner string(subject to well design criteria) at approximately 17,500 ft, forexample, and finished using a 8½ inch hole and 7 inch production liner52 at approximately 22,500 ft, for example. The sizes and methods usedherein are exemplary in nature as would be understood by one skilled inthe art having the benefit of this disclosure. For example, the systemsand methods described herein can be used in water depths less than orgreater than approximately 7,500 ft. Accordingly, the present inventionallows the well to be designed to effectively reduce the number ofcasing strings by using MPD, DGD, TTRD or UBD drilling technology tocontinually monitor subsurface pore pressures and set casing in theappropriate subsurface pressure regime.

The drill ship or drilling semi-submersible with identical drillingtechnology functionality utilized with the present invention will now bedescribed. The drill ship may include various types of equipment usefulin deep water drilling. As previously stated, an exemplary drill ship isthe 145-8×29-31 m DrillSLIM™. Use of DrillSLIM™, or similar designs,allows efficient movement around the world by the most direct routes(e.g., through the Suez and Panama Canals and under the BosporusBridge), which substantially reduces transit times and costs. The ship'shoisting tower arrangement mounted to a deck of the drill ship isspecifically designed to telescope inward to ensure when collapsed thetop of the hoist sheaves can pass under the bridges on the Panama andSuez canals and under the Bosphorous bridge into the Black Sea while thedrill ship is in transit draft. The hoisting tower would includesufficient racking capacity for a full drill string for water depths ofat least about approximately 7,500 ft. As an example using approximately7,500 ft water depth as a basis, the heaviest load of 355 tons (T)occurs when the approximately 7,500 ft of riser, two sets of BOP's,ancillary and travelling equipment are run. A 500 ton hoist rating canbe used to allow some margin of safety. The hoisting tower would furtherinclude hoisting capacity to hoist double drill pipe joints for use indrilling wells in water depths of at least approximately 7,500 ft; ahoisting capacity to hoist casing for use in drilling wells in waterdepths of at least approximately 7,500 ft; or combinations thereof.

In addition, the drill ship can also include active pit tank capacity tofully displace a largest hole volume over to another mud or brine systemfor use in drilling wells in water depths of at least approximately7,500 ft; full mud treatment and cuttings containment, with the abilityto mix new mud and brine simultaneously, for use in drilling wells inwater depths of at least approximately 7,500 ft; liquid and dry bulkstorage for use in drilling wells in water depths of at leastapproximately 7,500 ft; deck space and services for electric and slickline, cementing, well testing, well simulation, coiled tubing, MPD/UBDoperations, drill cutting operations, or combinations thereof for use indrilling wells in water depths of at least approximately 7,500 ft; orcombinations thereof. The floatable structure may further includevarious combinations of the types of equipment described herein.

For example, the active pit system can be 6,460 bbls (1027 m³) plus fivetreatment tanks of 60 bbls (9.5 m³) each. The active pits can be splitin half for two independent mud/brine systems with two independentautomated mud/brine mixing facilities for concurrent operations. Liquidstorage can include 9,749 bbls (1,550 m³) of drill water, 2,139 bbls(340 m³) of base oil, and 1,572 bbls (250 m³) of brine. Threeconventional triplex pumps with approximately 7,500 psi fluid ends canprovide for all downhole pumping operations. Solids control can beprovided by four linear motion shale shakers, a desander, a desilter, adegasser, and space for two contractor supplied centrifuges. Solidsdisposal can be via one double self cleaning screw conveyor feeding intoa big bag turntable station. Dry bulk storage can include six×60 m³tanks, (one bentonite, three barite and two cement) with three×6 m³surge tanks. The cement unit can be contractor supplied and also providepressure testing and emergency pumping services. Those ordinarilyskilled in the art having the benefit of this disclosure realize othertypes of equipment can be used with the present invention, such as thoseused in controlling mud and solids, as well as cement systems.

The exemplary drill ship may further include hoisting and handlingequipment. A single hoisting tower with a ram type hoist having a clearworking height of 120 ft for drilling, along with a top drive and doublejoints of range two drill pipe, can be included. Dead line compensationcan be included for drill string motion compensation. The hoisting towercan further include a hydraulic racking system with setback for 22,500ft of 5 inch drill pipe and drill collars. A remote operated ironroughneck can be provided on the drill floor 35 for tubular make-up andbreak-out. A skidding and trolley system below the substructure can beprovided for handling and storing the two×13⅝ inch BOP stacks and up totwo subsea Xmas trees. Additionally, at moon pool level, there can be aretractable dummy riser spider trolley to hang off the BOP while theload ring and telescopic joints are installed.

The exemplary drill ship described herein can further include threehydraulic knuckle boom cranes: a compensated crane rated to 120 T inport/60 T offshore for handling BOP equipment, Xmas trees, and forconstruction activities; a 20 T rated crane to serve the aft deck andmud treatment deckhouse; and a 25 T rated crane for loading tubularsfrom the quay to the riser racks. The systems and methods describedherein can also include two horizontal catwalks, one forward for risertransport and one aft for drill pipe/casing both at drill floor 35elevation. One gantry crane can be installed on the riser storage areaand one gantry crane over the aft pipe storage area. A tubular handlingoverhead crane and a vertical pipe elevator can be installed in the pipehold in the hull. Other types of hoisting and handling equipment thatcan be used in the present invention will be apparent to those of skillin the art having the benefit of this disclosure.

The exemplary drill ship described herein will also include rotatingequipment. For example, rotating the drill string can be a 500 tons ACmotor driven top drive. A conventional 49½ inch rotary table can befitted for tubular support and can be driven by a hydraulic motor forlimited rotational capability. Other suitable types of rotatingequipment will be apparent to those of skill in the art having thebenefit of this disclosure.

The exemplary drill ship described herein further includes drillingtools. In an aspect, for example, approximately 22,500 ft each of 5 inchand 3½ inch high grade drill pipe, and ten each of 8 inch, 6½ inch and4¾ inch drill collars, all with handling and fishing tools can beincluded. The types and amounts of drilling tools included will varydepending upon the needs of each system as will be apparent to those ofskill in the art having the benefit of this disclosure.

The exemplary drill ship also includes utility systems. The electricalpower system can include variable speed AC drives for the mud pumps andtop drive, with a normal drilling load of 3.0 Megawatts (MW). Thehoisting system can be hydraulically powered through a central HPU. Thetypes and amounts of utility systems included in embodiments of thepresent invention will vary depending upon the needs of each system aswill be apparent to those of skill in the art having the benefit of thisdisclosure.

The exemplary drill ship can be powered by six 4.7 MW main dieselelectric alternator sets with propulsion from five fixed pitch, variablespeed thrusters with a combined power of 17.3 MW. The thrusters can beconfigured for independent and integrated operation with the dynamicallypositioned vessel to IMO class 3. All systems can be designed andinstalled to ensure that adequate redundancy is maintained and that nosingle failure will result in loss of positional keeping or operationalperformance.

The exemplary drill ship can also have an endurance of sixty days(typically thirty days transit and thirty days dynamically positioned),and operations can be designed to be carried out without assistance fromother vessels. The ship's service speed can be around fourteen knots.The heli-deck can be rated for S61, S92, EC225 & Super Puma helicopters.One 25 m burner boom can be mounted on the port stern for flaringoperations.

Using embodiments of the present invention, smaller riser strings areused and less casing strings are necessary. As a result, smaller drillships can be used, in less hostile geological and pore pressure regimeenvironments where less casing is required, thereby cutting conventionaloperating costs in half and reducing well costs by half. Conventionaldual activity drill ships have four drill crews (two well centers),while the drill ships constructed and used in accordance withembodiments of the present invention are expected to have only two drillcrews (one well centre). The crew rate will be +/−70% of that of thelarger drill ships. Furthermore, the all up day spread rate (includingservices and fuel) for the large drill ship are expected to be in theregion of $750-$800,000/day, while the expectation for use of thesystems and methods described herein is expected to be one-half totwo-thirds that spread rate.

In addition, well intervention workovers into an existing subsea well tomove the “drainage point” in the reservoir using TTRD technology toincrease reserves base also becomes viable as the dual BOP/riser system5 will enable an RCH to be installed at surface to facilitate MPDdrilling technology, which is relevant when reservoir pore pressures arein decline causing convergences of the pore pressure-fracture gradientwindow. Without the high pressure riser of the present invention, thiscannot be achieved using conventional subsea stack-marine riser systems.

An exemplary embodiment of the current invention provides a subseaassembly for use in the recovery of hydrocarbons located beneath thesurface of a body of water, the assembly comprising an upper blow outpreventer (UBOP) located beneath a vessel floor; a high pressure riserstring located beneath the UBOP and a lower blow out preventer (LBOP)located beneath the riser string and operatively coupled to a wellhead.In an embodiment, the high pressure riser string has a pressure ratingthat is the same as a pressure rating of the UBOP and LBOP. In anotherembodiment, the pressure rating of the UBOP, riser string and LBOP is atleast 10,000 psi. In the alternative, the assembly is adapted to performat least one of a managed pressure drilling, underbalanced drilling,dual gradient drilling or through tubing rotary drilling operation. In ayet further embodiment, the riser string is sized for running casinghaving an API size less than or equal to 13⅜″. In some embodiments, theassembly further includes a rotating control head. The vessel may alsobe adapted to drill wells in water depths of at least 7,500 ft.

An exemplary embodiment of the present invention provides a subseaassembly for use in subsea operations, the assembly comprising a slipjoint assembly located beneath a vessel floor; a rotating control headlocated beneath the slip joint assembly; an upper blow out preventerlocated beneath the rotating control head; an upper stress joint locatedbeneath the UBOP; a high pressure riser string located beneath the upperstress joint; a lower stress joint located beneath the high pressureriser string; a lower blow out preventer located beneath the lowerstress joint; and a wellhead located beneath the LBOP such that theburst strength of the UBOP, the high pressure riser string and the LBOPprovide a uniform pressure containment ability from the top to thebottom of said subsea assembly. In another embodiment, the riser stringhas a pressure rating that is the same as a pressure rating of the UBOPand LBOP. In yet another embodiment, the assembly is used in an offshoredeepwater environment. In the alternative, the assembly is adapted toperform at least one of a managed pressure drilling, underbalanceddrilling, dual gradient drilling or through tubing rotary drillingoperation. In yet another embodiment, the riser string is sized forrunning casing having an API size less than or equal to 13⅜″. The vesselmay also have a length of no more than 148 meters and a width of no morethan 28 meters. In yet another embodiment, the vessel is adapted todrill wells in water depths of at least 7,500 ft.

An exemplary subsea assembly, of the current invention, for use in theexploration for and recovery of hydrocarbons located beneath the surfaceof a body of water, connects a support structure to a deepwater subseawellhead while the assembly is specifically configured to support DGDand UBD and related completion and production operations. In anembodiment, such a subsea assembly has an upper assembly, adjacent thefloating structure, that includes a slip joint assembly, a rotatingcontrol head assembly; and an UBOP with a plurality of rams, a highpressure riser assembly connecting the UBOP to LBOP that is configuredto permit DGD and UBD and a lower assembly having a LBOP with aplurality of rams, at least one of which is a shear ram and a wellhead,wherein the UBOP, the LBOP, and the high pressure riser assembly provideuniform burst strength characteristics to said subsea assembly from theupper assembly through and including the lower assembly. In anotherembodiment, the rotating control head includes a high pressure spacerjoint, a load ring and a flange assembly. In yet a further embodiment,the upper assembly can additionally include a diverter assembly, a flexjoint and a slip joint assembly.

An exemplary methodology of the present invention provides a method foruse in a subsea operation, the method comprising the steps of (a)providing a slip joint assembly located beneath a vessel floor; (b)providing a rotating control head located beneath the slip jointassembly; (c) providing an upper blow out preventer (“UBOP”) locatedbeneath the rotating control head; (d) providing an upper stress jointlocated beneath the UBOP; (e) providing a high pressure riser stringlocated beneath the upper stress joint; (f) providing a lower stressjoint located beneath the riser string; (g) a lower blow out preventer(“LBOP”) located beneath the lower stress joint; and (f) providing awellhead located beneath the LBOP such that the burst strength of theUBOP, the high pressure riser string and the LBOP provide a uniformpressure containment ability from the top to the bottom of said subseaassembly.

In another methodology, step (e) further comprises the step of providingthe riser string with a pressure rating that is the same as a pressurerating of the UBOP and LBOP. In yet another methodology, the methodfurther comprises the step of performing the subsea operation in anoffshore deepwater environment. In another methodology, the methodfurther comprises the step of performing at least one of a managedpressure drilling, dual gradient drilling, underbalanced drilling, orthrough tubing rotary drilling operation. In another methodology, themethod further comprises the step of tripping a liner having an API sizeless than or equal to 13⅜″ through the riser string. In yet another, themethod further comprises the step of providing the vessel with a lengthof no more than 148 meters and a width of no more than 28 meters

Another exemplary embodiment of the present invention provides a subseaassembly for use in subsea operations, the assembly comprising an upperblow out preventer (“UBOP”) located beneath a vessel floor; a riserstring located beneath the UBOP; and a lower blow out preventer (“LBOP”)located beneath the riser string and operatively coupled to a wellhead.In another embodiment, the riser string has a pressure rating that isthe same as a pressure rating of the UBOP and LBOP. In yet anotherembodiment, a pressure rating of the UBOP, riser string, and LBOP is atleast 10,000 psi. In another embodiment, the assembly is used in anoffshore deepwater environment. In yet another embodiment, the assemblyis adapted to perform at least one of a managed pressure drilling,underbalanced drilling, or through tubing rotary drilling operation. Inyet another embodiment, the riser string is sized for running casinghaving an API size less than or equal to 13⅜″. An exemplary embodimentmay also comprise a rotating control head. In another embodiment, thevessel has a length of no more than 148 meters and a width of no morethan 28 meters. In yet another embodiment, the vessel is adapted todrill wells in water depths of at least 7,500 ft.

Another exemplary methodology of the present invention provides a methodfor use in subsea operations, the method comprising the steps of (a)providing a vessel having a floor; (b) providing an upper blow outpreventer (“UBOP”) located beneath the floor; (c) providing a highpressure riser string located beneath the UBOP; (d) providing a lowerblow out preventer (“LBOP”) located beneath the riser assembly; and (e)connecting the LBOP to a wellhead beneath the LBOP. In anothermethodology, the method further comprises the step of providing theriser string with a pressure rating that is the same as a pressurerating of the UBOP and LBOP. In yet another, the method furthercomprises the step of providing the UBOP, riser string, and LBOP with apressure rating of at least 10,000 psi. In another methodology, themethod further comprises the step of performing the subsea operations inan offshore deepwater environment. In yet another, the method furthercomprises the step of performing at least one of a managed pressuredrilling, underbalanced drilling, dual gradient drilling, or throughtubing rotary drilling operation. In another methodology, the methodfurther comprises the step of tripping liner down the riser string, theliner having an API size less than or equal to 13⅜″. In yet anothermethodology, the method further comprises the step of locating arotating control head beneath the UBOP. In another exemplarymethodology, step (a) further comprises the step of providing the vesselwith dimensions of no more than 148 meters in length and no more than 28meters in width. In yet another, the method further comprises the stepof drilling a well at a water depth of at least 7,500 ft.

All of the embodiments and methodologies of the present inventiondisclosed and claimed herein can be made and executed without undueexperimentation in light of the present disclosure. While the inventionis susceptible to various modifications and alternative forms, specificembodiments have been shown by way of example in the drawings and havebeen described in detail herein. However, it should be understood thatthe invention is not intended to be limited to the particular formsdisclosed. For example, it will be apparent that certain components thatare useful in drilling can be substituted for the components describedherein, or additional components can be used to drill the deep waterwells, while achieving the same or similar results. Accordingly, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the invention as defined by theappended claims.

What is claimed is:
 1. A subsea assembly for use in the recovery ofhydrocarbons located beneath the surface of a body of water, said subseaassembly connecting a floating support structure to a deepwater subseawellhead, said subsea assembly comprising: (a) a rotating control headassembly functionally connected to said floating support structure; (b)an upper blow out preventer located beneath and functionally connectedto said rotating control head assembly; (c) a high pressure riser stringlocated beneath and functionally connected to said upper blowoutpreventer said high speed riser string providing pressure integrity tosaid subsea assembly; (d) a lower riser package located beneath andfunctionally connected to said high pressure riser string; and (e) alower blowout preventer located beneath said lower riser package, saidlower blowout preventer being functionally coupled to a wellhead.
 2. Anassembly as defined in claim 1, wherein the high pressure riser stringhas a pressure rating that is the same as a pressure rating of the upperblowout protector and the lower blowout preventer.
 3. An assembly asdefined in claim 2 wherein a pressure rating of the upper blowoutpreventer, the high pressure riser string, and the lower blowoutpreventer is at least 10,000 psi.
 4. An assembly as defined in claim 1,wherein the subsea assembly is adapted to perform at least one of amanaged pressure drilling, underbalanced drilling, dual gradientdrilling or through tubing rotary drilling using said rotating controlhead assembly
 5. An assembly as defined in claim 1, wherein the highpressure riser string is sized for running casing having an API sizeless than or equal to 13⅜″.
 6. An assembly as defined in claim 1,wherein said floating support structure is adapted to drill wells inwater depths of at least 7,500 ft.
 7. A subsea assembly for use in therecovery of hydrocarbons located beneath the surface of a body of water,said subsea assembly connecting a floating support structure to a deepwater subsea wellhead, said subsea assembly comprising: (a) a slip jointassembly located beneath and functionally connected to said floatingsupport structure; (b) a rotating head assembly being functionallyconnected to said slip joint assembly; (c) an upper blowout preventerlocated beneath said rotating control head assembly; (d) a high pressureriser string located beneath and functionally connected to said upperstress joint; (e) a lower riser package located beneath and functionallyconnected to said high pressure riser string; (f) a lower blowoutpreventer located beneath and functionally connected to said lower riserpackage joint; and (g) a wellhead located beneath the lower blowoutpreventer; wherein the pressure rating of said upper blowout preventer,said high pressure riser string, and said lower blowout preventerprovide a uniform pressure containment ability from the top to thebottom of said subsea assembly.
 8. An assembly as defined in claim 7,wherein said high pressure riser string has a pressure rating that isthe same as a pressure rating of said upper blowout preventer and saidlower blowout preventer.
 9. An assembly as defined in claim 7, whereinthe assembly is adapted to perform at least one of a managed pressuredrilling, underbalanced drilling, dual gradient drilling or throughtubing rotary drilling operation using said rotating control headassembly.
 10. An assembly as defined in claim 7, wherein the riserstring is sized for running casing having an API size less than or equalto 13⅜″.
 11. An assembly as defined in claim 7, wherein the vessel isadapted to drill wells in water depths of at least 7,500 ft.
 12. Asubsea assembly for use in the exploration for and recovery ofhydrocarbons located beneath the surface of a body of water, said subseaassembly connecting a floating support structure to a deepwater subseawellhead, said assembly being specifically configured to support dualgradient drilling and underbalanced drilling and related completion andproduction operations, said subsea assembly comprising: (a) an upperassembly located adjacent to and functionally connected to said floatingstructure, said upper assembly including: (i) a slip joint assembly;(ii) a rotating control head assembly; and (iii) an upper blowoutpreventer, said upper blowout preventer including a plurality of rams;(b) a high pressure riser assembly connecting said upper blowoutpreventer to a lower riser package, said high pressure riser assemblybeing configured to permit dual gradient drilling and underbalanceddrilling operations and wherein the pressure rating of said highpressure riser assembly is substantially the same as the pressure ratingof said upper blowout preventer; (c) a lower riser package functionallyconnecting to said high pressure riser assembly to a lower blowoutpreventer, said lower riser package comprising apparatus fordisconnecting said high pressure riser assembly from said lower blowoutpreventer when an emergency disconnect is required; and (d) a lowerblowout preventer functionally connected to said lower riser package;wherein said upper blowout preventer, said lower blowout preventer, andsaid high pressure riser assembly provide uniform pressure ratingcharacteristics of at least 10,000 psi to said subsea assembly from theupper assembly through and including said lower assembly.
 13. The subseaassembly of claim 12 wherein said rotating control head assemblyincludes: (a) a rotating control head; (b) a high pressure spacer joint;(c) a load ring, and (d) a flange assembly.
 14. The subsea assembly ofclaim 12 wherein said upper assembly includes: (a) a diverter assembly,(b) a flex joint, and (c) a slip joint assembly.
 15. A method for use ina subsea operation, the method comprising the steps of: (a) providing aslip joint assembly located beneath a vessel floor; (b) providing arotating control head located beneath the slip joint assembly; (c)providing an upper blowout preventer located beneath the rotatingcontrol head; (d) providing an upper stress joint located beneath theupper blowout preventer; (e) providing a high pressure riser stringlocated beneath the upper stress joint; (f) providing a lower stressjoint located beneath the riser string; (g) a lower blowout preventerlocated beneath the lower stress joint; and (h) providing a wellheadlocated beneath the lower blowout preventer; wherein the pressure ratingof said upper blowout preventer, said high pressure riser string, andsaid lower blowout preventer provide a uniform pressure containmentability from the top to the bottom of said subsea assembly.
 16. A methodas defined in claim 15, wherein step (e) further comprises the step ofproviding the high pressure riser string with a pressure rating that isthe same as a pressure rating of said upper blowout preventer and saidlower blowout preventer.
 17. A method as defined in claim 15, furthercomprising the step of performing at least one of a managed pressuredrilling, underbalanced drilling, dual gradient drilling or throughtubing rotary drilling using said rotating control head assembly.
 18. Amethod as defined in claim 15, further comprising the step of tripping aliner having an API size less than or equal to 13⅜″ through the riserstring.